In recent years, industrial and utility concerns with deregulation and operational costs have strengthened demands for increased power plant efficiency. The Rankine cycle power plant, which typically utilizes water as the working fluid, has been the mainstay for the utility and industrial power industry for the last 150 years. In a Rankine cycle power plant, heat energy is converted into electrical energy by heating a working fluid flowing through tubular walls, commonly referred to as waterwalls, to form a vapor, e.g., turning water into steam. Typically, the vapor will be superheated to form a high pressure vapor, e.g., superheated steam. The high pressure vapor is used to power a turbine/generator to generate electricity.
Conventional Rankine cycle power generation systems can be of various types, including direct-fired, fluidized bed and waste-heat type systems. In direct fired and fluidized bed type systems, combustion process heat is generated by burning fuel to heat the combustion air which in turn heats the working fluid circulating through the systems' waterwalls. In direct-fired Rankine cycle power generation systems the fuel, commonly pulverized-coal, gas or oil, is ignited in burners located in the waterwalls. In bubbling fluidized Rankine cycle power generation systems pulverized-coal is ignited in a bed located at the base of the boiler to generate combustion process heat. Waste-heat Rankine cycle power generation systems rely on heat generated in another process, e.g., incineration, for process heat to vaporize, and if desired superheat, the working fluid. Due to the metallurgical limitations, the highest temperature of the superheated steam does not normally exceed 1050.degree. F. (566.degree. C.) . However, in some "aggressive" designs, this temperature can be as high as 1100.degree. F. (593.degree. C.).
Over the years, efficiency gains in Rankine cycle power systems have been achieved through technological improvements which have allowed working fluid temperatures and pressures to increase and exhaust gas temperatures and pressures to decrease. An important factor in the efficiency of the heat transfer is the average temperature of the working fluid during the transfer of heat from the heat source. If the temperature of the working fluid is significantly lower than the temperature of the available heat source, the efficiency of the cycle will be significantly reduced. This effect, to some extent, explains the difficulty in achieving go further gains in efficiency in conventional, Rankine cycle-based, power plants.
In view of the above, a departure from the Rankine cycle has recently been proposed. The proposed new cycle, commonly referred to as the Kalina cycle, attempts to exploit the additional degree of freedom available when using a binary fluid, more particularly an ammonia/water mixture, as the working fluid. The Kalina cycle is described in the paper entitled: "Kalina Cycle System Advancements for Direct Fired Power Generation", co-authored by Michael J. Davidson and Lawrence J. Peletz, Jr., and published by Combustion Engineering, Inc., of Windsor, Conn. Efficiency gains are obtained in the Kalina cycle plant by reducing the energy losses during the conversion of heat energy into electrical output.
A simplified conventional direct-fired Kalina cycle power generation system is illustrated in FIG. 1 of the drawings. Kalina cycle power plants are characterized by three basic system elements, the Distillation and Condensation Subsystem (DCSS) 100, the Vapor Subsystem (VSS) 110 which includes the boiler 142, superheater 144 and recuperative heat exchanger (RHE) 140, and the turbine/generator subsystem (TGSS) 130. The DCSS 100 and RHE 140 are sometimes jointly referred to as the Regenerative Subsystem (RSS) 150. The boiler 142 is formed of tubular walls 142a and the superheater 144 is formed of tubular walls and/or banks of fluid tubes 144a. A heat source 120 provides process heat 121. A portion 123 of the process heat 121 is used to vaporize the working fluid in the boiler 142. Another portion 122 of the process heat 121 is used to superheat the vaporized working fluid in the superheater 144.
During normal operation of the Kalina cycle power system of FIG. 1, the ammonia/water working fluid is fed to the boiler 142 from the RHE 140 by liquid stream FS 5 and from the DCSS 100 by liquid stream FS 7. The working fluid is vaporized, i.e., boiled, in the tubular walls 142a of the boiler 142. The FS rich working fluid stream 20 from the DCSS 100 is also vaporized in the heat exchanger(s) of the RHE 140. In one implementation, the vaporized working fluid from the boiler 142 along with the vaporized working fluid FS 9 from the RHE 140, is further heated in the tubular walls/fluid tube bank 144aof the superheater 144. The superheated vapor from the superheater 144 is directed to and powers the TGSS 130 as FS vapor 40 so that electrical power 131 is generated to meet the load requirement. In an alternative implementation, the RHE 140 not only vaporizes but also superheats the rich stream FS 20. In such a case, the superheated vapor flow FS 9' from the RHE 140 is combined with the superheated vapor from the superheated vapor from the superheater 144 to form FS vapor flow 40 to the TGSS 130.
The expanded working fluid FS extraction 11 egresses from the TGSS 130, e.g., from an intermediate pressure (IP) or a low pressure (LP) turbine (not shown) within the TGSS 130, and is directed to the DCSS 100. This expanded working fluid is, in part, condensed in the DCSS 100. Working fluid condensed in the DCSS 100, as described above, forms feed fluid FS 7 which is fed to the boiler 142. Another key feature of the DCSS 100 is the separation of the working fluid egressing from TGSS 130 into ammonia rich and ammonia lean streams for use by the VSS 110. In this regard, the DCSS 100 separates the expanded working fluid into an ammonia rich working fluid flow FS rich 20 and an ammonia lean working fluid flow FS lean 30. Waste heat 101 from the DCSS 100 is dumped to a heat sink, such as a river or pond. The rich and lean flows FS 20, FS 30 respectively, are fed to the RHE 140. Another somewhat less expanded hot working fluid FS extraction 10 egresses from the TGSS 130, e.g., from a high pressure (HP) turbine (not shown) within the TGSS 130, and is directed to the RHE 140. Heat is transferred from the expanded working fluid FS extraction 10 and the working fluid FS lean stream 30 to the rich working fluid flow FS rich 20, to thereby vaporize the rich flow FS 20 and condense, at least in part, the expanded working fluid FS extraction 10 and FS lean working fluid flow 3Q, in the RHE 140. As discussed above, the vaporized rich flow FS 20 is fed to either the superheater 144, along with vaporized feed fluid from the boiler 142, or is combined with the superheated working fluid from the superheater 142 and fed directly to the TGSS 130. The condensed expanded working fluid from the RHE 140 forms part of the feed flow, i.e., flow FS 5, to the boiler 142, as has been previously described.
FIG. 2 details a portion of the RHE 140 of VSS 110 of FIG. 1. As shown, the RHE 140 receives ammonia-rich, cold high pressure stream FS rich 20 from DCSS 100. Stream FS rich 20 is heated by ammonia-lean hot low pressure stream FS 3010. The stream FS 3010 is formed by combining the somewhat lean hot low pressure FS extraction stream 10 from TGSS 130 with the lean hot low pressure stream FS 30 from DCSS 100, these flows being combined such that stream FS 30 dilutes stream FS 10 resulting in a desired concentration of ammonia in stream FS 3010.
Heat energy 125, is transferred from stream FS 3010 to stream FS rich 20. As discussed above, this causes the transformation of stream FS 20 into a high pressure vapor stream FS 9 or the high pressure superheated vapor stream FS 9', depending on the pressure and concentration of the rich working fluid stream FS 20. This also causes the working fluid stream FS 3010 to be condensed and therefore serve as a liquid feed flow FS 5 to the boiler 142.
As previously indicated, in one implementation the vapor stream FS 9 along with the vapor output from boiler 142 forms the vapor input to the superheater 144, and the superheater 144 superheats the vapor stream to form superheated vapor stream 40 which is used to power TGSS 130. Alternatively, the superheated vapor steam FS 9' along with the superheated vapor output from the superheater 144 forms the superheated vapor stream FS 40 to the TGSS 130.
FIG. 3 illustrates exemplary heat transfer curves for heat exchanges occurring in the RHE 140 of FIG. 2. A typical Kalina cycle heat exchange is represented by curves 520 and 530. As shown, the temperature of the liquid binary working fluid FS 20 represented by curve 520 increases as a function of the distance of travel of the working fluid through the heat exchanger of the RHE 140 in a substantially linear manner. That is, the temperature of the working fluid continues to increase even during boiling as the working fluid travels through the heat exchanger of the RHE 140 shown in FIG. 2. At the same time, the temperature of the liquid working fluid FS 3010 represented by curve 530 decreases as a function of the distance of travel of this working fluid through the heat exchanger of the RHE 140 in a substantially linear manner.
That is, as heat energy 125 is transferred from working fluid FS 3010 to the working fluid stream FS 20 as both fluid streams flow in opposed directions through the RHE 140 heat exchanger of FIG. 2, the binary working fluid FS 3010 loses heat and the binary working fluid stream FS 20 gains heat at substantially the same rate within the Kalina cycle heat exchangers of the RHE 140.
In contrast, a typical Rankine cycle heat exchange is represented by curve 510. As shown, the temperature of the water or water/steam mixture forming the working fluid represented by curve 510 increases as a function of the distance of travel of the working fluid through a heat exchanger of the type shown in FIG. 2 only after the working fluid has been fully evaporated, i.e.,, vaporized. The portion 511 of curve 510 represents the temperature of the water or water/steam mixture during boiling. As indicated, the temperature of the working fluid remains substantially constant until the boiling duty has been completed. That is, in a typical Rankine cycle, the temperature of the working fluid does not increase during boiling. Rather, as indicated by portion 512 of curve 510, it is only after full vaporization, i.e.,, full phase transformation, that the temperature of the working fluid in a typical Rankine cycle increases beyond the boiling point temperature of the working fluid, e.g., 212 degrees Fahrenheit.
As will be noted, the temperature differential between the stream represented by curve 530, which transfers the heat energy, and the Rankine cycle stream represented by curve 510, which absorbs the heat energy, continues to increase during phase transformation. The differential becomes greatest just before complete vaporization of the working fluids. In contrast, the temperature differential between the stream represented by curve 530, and the Kalina cycle stream represented by curve 520, which absorbs the heat energy, remains relatively small, and substantially constant, during phase transformation. This further highlights the enhance efficiency of Kalina cycle heat exchange in comparison to Rankine cycle heat exchange.
As indicated above, the transformation in the RHE 140 of the liquid or mixed liquid/vapor stream FS 20 to vapor or superheated vapor stream FS 9 or 9' is possible in the Kalina cycle because, the boiling point of rich cold high pressure stream FS 20 is substantially lower than that of lean hot low pressure stream FS 3010. This allows additional boiling, and in some implementations superheating, duty to be performed in the Kalina cycle RHE 140 and hence outside the boiler 142 and/or superheater 144. Hence, in the Kalina cycle, a greater portion of the process heat 121 can be used for superheating vaporized working fluid in the superheater 144, and less process heat 121 is required for boiling duty in the boiler 142. The net result is increased efficiency of the power generation system when compared to a conventional Rankine cycle type power generation system. FIG. 4 further depicts the TGSS 130 of FIG. 1. As illustrated, the TGSS 13Q in a Kalina cycle power generation system is driven by a high pressure superheated binary fluid vapor stream FS 40. Relatively lean hot low pressure stream FS extraction 10 is directed from, for instance the exhaust of an HP turbine (not shown) within the TGSS 130 to the RHE 140 as shown in FIGS. 1 and 2. A relatively lean cooler, even lower pressure flow FS extraction 11 is directed from, for instance, the exhaust of an IP or LP turbine (not shown) within the TGSS 130 to the DCSS 100 as shown in FIG. 1. As has been discussed to some extent above and will be discussed further below, both FS extraction flow 10 and FS extraction flow 11 retain enough heat to transfer energy to still cooler higher pressure streams in the DCSS 100 and RHE 140.
FIG. 5 further details the Kalina cycle power generation system of FIG. 1 for a once through, i.e.,, non-recirculating, system configuration. As shown, working fluid FS 5 and FS 7 from the RHE 140 and DCSS 100 are combined to form a feed fluid stream FS 57 which is fed to the bottom of the boiler 142. The working fluid 57 flows through the boiler tubes 142a where the working fluid 57 is exposed to process heat 123. The working fluid is heated and vaporized in the boiler tubes 142a, while cooling the boiler walls. Sufficient liquid working fluid must be supplied by feed stream FS 57 to provide an adequate flow to the boiler tubes 142a to ensure proper cooling during system operation. Without an adequate flow to the boiler tubes 142a, the boiler tubes 142a can become overheated causing a premature failure of the boiler tubes 142a, particularly in the combustion chamber, and requiring system shut-down for repair. The heated working fluid rises in the boiler tubes 142a and the fully vaporized working fluid stream is directed from the boiler tubes 142a as stream FS 8 and combined with the vapor stream FS 9 from the RHE 140. The combined vaporized fluid stream FS 89 is directed to the superheater 144, where it is exposed to process heat 122. The high pressure superheated vapor flow FS 40 is directed from the superheater 144.
The TGSS 130, as shown, includes both a HP turbine 130' and an IP turbine 130". The superheated high pressure vapor stream FS 40 is directed first to the HP turbine 130' of the TGSS 130 and then to the IP turbine 130" of the TGSS 130. The vapor flow FS 40 must be sufficient to provide the necessary energy to drive the turbines so that the required power is generated. The lower pressure hot working fluid exhausted from the HP turbine 130' is split into a lower pressure vapor working fluid stream FS 40' to the boiler 142 where it is reheated and then sent to the IP turbine 130" and an extraction flow FS 40" to the RHE 140. Typically, approximately 50% of the exhaust flow from the HP turbine 130' is split off as stream FS 40" to the RHE 140, although this may vary. The even lower pressure hot working fluid exhausted from the IP turbine 130" is split into a working fluid stream FS 11 which is fed to the DCSS 100 and extraction flow FS 40'" which is fed to the RHE 140. It will be understood that the TGSS 130 could also include other turbines, e.g., a LP turbine to which a portion of the fluid flow from the IP turbine might be first directed before being directed from the TGSS 130 to the DCSS 100. The lean hot working fluid extraction streams FS 40" and FS 40'"from the TGSS 130 are combined to form stream FS 10, which is further combined, as previously discussed, with lean hot working fluid stream FS 30 from the DCSS 100 to form a hot working fluid stream 3010. Stream 3010 is directed on to the RHE 140.
The RHE 140, as previously described receives the hot stream FS 3010 and a rich cold fluid stream FS 20 from the DCSS 100. Heat is transferred from the stream FS 3010 to vaporize stream FS 20. During this process, the steam FS 3010 is condensed to form condensate 3010' which is fed to the boiler 142 as liquid stream FS 5.
FIG. 6 illustrates a furnace structure 146 incorporating both the boiler 142 and the superheater 144. As shown, the furnace structure 146 has a primary (lower) section 146', a secondary (upper) section 146", and a backpass section 146"'. The boiler 142 is located in the lower section 146' and the superheater 144 is located in the upper section 146". The heat source 120, which in this instance is shown to be a pair of direct-fired burners 124 located in the walls of the boiler 142 but, as previously described, may also be waste heat or a fluidized bed, generates process heat within the furnace structure 146. The backpass section 146"', which generally directs combustion and flue gases 147 to an exhaust stack (not shown), can also be used to support further heat exchange devices, which are typically operating at temperatures that are lower than the operating temperatures in either the boiler 142 or the superheater 144 due to the relatively lower temperature of the combustion and flue gases 147 passing through the backpass section 146"'.
As previously described, the boiler 142 is formed of tubular walls 142a, and the superheater 144 is formed of tubular walls and/or banks of fluid tubes 144a. The tubular walls 142a typically include a plurality of wall fluid tubes 142a', and the tubular walls and/or banks of fluid tubes 144atypically include a plurality of wall fluid tubes 144a' and/or suspended fluid tubes 144a" , respectively, as shown. The wall fluid tubes 142a', the wall fluid tubes 144a', and the suspended fluid tubes 144a" are typically interconnected through headers (not shown) in the furnace structure 146.
As also previously described, working fluid passes through the tubular walls 142a of the boiler 142 and the tubular walls and/or banks of fluid tubes 144aof the superheater 144 so as to generate superheated vapor for powering the TGSS 130 and generating electrical power. However, the working fluid passing through the tubular walls 142a of the boiler 142 and the tubular walls and/or banks of fluid tubes 144aof the superheater 144 also works to cool the walls of the furnace structure 146, particularly in the boiler 142, or wherever else the heat source 120 might be located. That is, the working fluid works to protect the walls of the furnace structure 146 from the high temperatures generated by the heat source 120 and thereby prevent material and/or structural damage to the furnace structure 146.
During normal operation, the walls of the furnace structure 146 are generally protected from overheating by flows of the liquid working fluid stream FS 5 from the RHE 140, the liquid working fluid stream FS 7 from the DCSS 100, and, to a lesser degree, the vaporized working fluid stream FS 9 from the RHE 140. However, during start-up and/or low-load operation there is typically insufficient vapor flow through the tubular walls 142a of the boiler 142 and the tubular walls and/or banks of fluid tubes 144a of the superheater 144 to cool the walls of the furnace structure 146. Thus, the walls of the furnace structure 146, particularly in the boiler 142, or wherever else the heat source 120 might be located, are susceptible to being overheated and damaged during start-up and/or low-load operation.
Further, even during normal operation the flow rate through the tubular walls 142a of the boiler 142 and the tubular walls and/or banks of fluid tubes 144aof the superheater 144 may be insufficient to cool the walls of the furnace structure 146. That is, despite the fact that some working fluid may be flowing through the tubular walls 142a of the boiler 142 and the tubular walls and/or banks of fluid tubes 144a of the superheater 144, the flow rate of such working fluid may be insufficient to cool the walls of the furnace structure 146. For example, this may occur when the heat source 120 is generating very high process heat, and/or when the entire furnace structure 146 is operating as a superheater. Thus, the walls of the furnace structure 146, particularly in the boiler 142, or wherever else the heat source 120 might be located, are susceptible to being overheated and damaged even during normal operation.
One proposal to overcome an overheating problem in a furnace is described in U.S. Pat. No. 5,588,298 ('298 patent), issued to Kalina et al. on Dec. 31, 1996, and hereby incorporated herein by reference. In the '298 patent, Kalina et al. describe a furnace system having two independent combustion zones and two corresponding independent heat exchanger systems in a single furnace system. The two independent heat exchanger systems support two totally separate working fluid streams, which may or may not be combined in an external power system.
One supposed benefit of the furnace system described in the '298 patent is that the temperature in each combustion zone can be independently controlled, thereby preventing excessive tube metal temperatures and subsequent damage to the walls of the furnace. However, there are also several disadvantages associated with the furnace system described in the '298 patent. One such disadvantage is that there are two totally separate combustion systems, as well as two totally separate heat exchanger systems and working fluid streams, to maintain. Another disadvantage is that two separate control systems are required to control and coordinate the two totally separate combustion and heat exchanger systems. A further disadvantage is that temperature differences between the two totally separate combustion zones and corresponding independent heat exchanger systems can result in material expansion differences which can cause joint failures in the walls of the furnace system. The above-stated disadvantages are prevalent in any furnace system employing two or more combustion zones and/or two or more heat exchanger systems in a single furnace.
In view of the above, it is readily apparent that a satisfactory solution to the problem of furnace wall overheating in a Kalina cycle power generation system has yet to be discovered. Accordingly, it would be desirable to overcome the above-described problems and disadvantages and provide a technique for cooling furnace walls in a Kalina cycle power generation system.